Good day ladies and gentlemen, and welcome to the Targa Resource Fourth Quarter 2016 Earnings Webcast. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference call maybe recorded I'd now like to introduce your host for today's conference, Ms. Jennifer Kneale, Vice President of Finance. Ma'am, you may begin.

Thank you, Chanel. I'd like to welcome everyone to our fourth quarter 2016 investor call for Targa Resources Corp. Before we get started, I'd like to mention that Targa Resources Corp., Targa, TRC or the company has published its earnings release, and an updated investor presentation which are available on our website www.targaresources.com. Any statements made during this call that might include the company's expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provision of the Securities Act of 1933 and 1934. Please note that actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings including the company's Annual Report on Form 10-K for the year ended December 31, 2015 and quarterly reports on Form 10-Q. Pat McDonie, EVP of Southern Field Gathering and Processing; Danny Middlebrooks, EVP of Northern Field Gathering and Processing, our North Dakota position and Scott Pryor, EVP of Logistics and Marketing our downstream business, will be joining Joe Bob Perkins, CEO and Matt Meloy, CFO in our scripted remarks. Joe Bob will begin the call and will then turn it over to Matt for discuss fourth quarter and full year 2016 results, and then Pat, Danny and Scott will discuss their business areas in that order. After closing remarks from Joe Bob we will then open the call up to questions. With that, I'll turn the coal call over to Joe Bob.

Thanks, Jen. Good morning, and thanks to everyone for joining. As we wrap up 2016 reporting, we are also going to try to cover our current expectations for 2017, including the discussion of the industry trends and activities that are driving those expectations. We spent much of 2015 and 2016 taking some very important steps to position Targa for success across a range of commodity price environments. And now that we are fueling some commodity price stability at levels of support, customer activity and volumes, we believe that Targa has a very positive outlook for 2017 and beyond. That positive outlook is highlighted by, first, a strong interconnected Targa Permian footprint was significant exposure to both Midland and Delaware activity, both of which are augmented by our recent acquisition announced on January 23rd. Secondly, Targa assets in both the STACK and SCOOP, where we are seeing activity levels increase, then positions in other E&P basin where Targa volumes are likely to outperform overall basin levels due to the strength of our asset position and due to the quality producers that we are serving. As evidenced by our Eagle and Bakken activities, for example. And of course, our Targa downstream infrastructure poised to benefit from some of the changing domestic and global market dynamics, especially as world-class PetChem crackers come online on the Golf Coast later this year and next year. And across all of our businesses where Targa commercial operations in future potential growth opportunities are supported by attractive partnerships, mutually beneficial customer relationships, a strong balance sheet, demonstrated access to capital markets and a loyal and talented workforce. 2017 is off to an exciting start for us at Targa, highlighted by the announcement on January 23rd that we were acquiring very nicely fitting additional assets in the Delaware and…

All right. Thanks, Joe Bob. I will begin by discussing our fourth quarter results and will provide some 2017 financial guidance as I move through my remarks. Targa's reported adjusted EBITDA for the fourth quarter was about $298 million, which as anticipated by remarks on our third quarter call was the highest quarter of 2016. Strong fourth quarter results were due largely to continued growth in our Permian G&P assets and strong performance in our downstream business, which included the partial recognition the approximately $40 million payment received from Noble i in October. Let's pause briefly to discuss the payments associated with the Noble crude and condensate splitter in a little bit more detail. We received approximately $40 million from Noble in October 2016, and the entirety is included in destructible cash flow for the fourth quarter. The contribution to adjusted EBITDA will be amortized over four quarters beginning in the quarter received, so for the fourth of 2016 approximately $10 million of adjusted EBITDA was recognized. A full explanation of our treatment of the splitter payment can be found on slide 38 of the investor presentation that was recently posted to our website this morning. Reported net maintenance capital expenditures were $28 million in the fourth quarter of 2016, compared to $24 million in the fourth quarter of 2015 and total net maintenance CapEx for 2015 was approximately $80 million. We currently expect approximately $110 million of net maintenance capital for 2007. Turning now to our segment level results, I'll go over our performance for the fourth quarter on a year-over-year basis. For the gathering and processing segment, reported operating margin for the fourth quarter of 2016 increased by 21% compared to last year, primarily due to higher commodity prices, and higher Inlet volumes in the Permian basin with…

Thanks, Matt. And good morning, everyone. Looking back on 2016, I am extremely pleased with our performance in the field G&P segment, and more importantly, looking forward, I'm very excited about the opportunities that we see across our outstanding footprint of assets. We have a number of capital projects in progress, which obviously speaks to our expectations and the expectations of our producers for arising activity, which should support build G&P Inlet volume growth that Joe Bob mentioned earlier. In SouthTX, our Raptor plant will be ramping up during the first quarter and will be fully operational in early April. Our JV partner, Sanchez Production Partners and Targa have jointly agreed to spend a limited amount of capital to add compression to increase total plant capacity to 260 million cubic feet a day from the originally planned 200 million cubic feet a day, a high-impact, highly capital efficient expansion feature designed into the plant already under construction. The expansion decision highlights our continuing joint optimism for activity on our system in the Western part of the Eagle Ford. In WestTX, the restart of our Benedum plant is slated for a first quarter 2017 in-service date. The capacity expansion at Midkiff is planned for a second quarter of 2017 in-service date and the new 200 million cubic feet per day Joyce plant is expected to be in service in the first quarter of 2018. These projects are on track and demonstrate continued optimism by Pioneer and Targa related to producer activity in the growth of volumes on our WestTXx venture. As also mentioned earlier, given our January acquisition announcement, we expect to connect the acquired assets in Martin County to our WestTX system at the Buffalo plant soon after transaction close. Given the activity levels that we are seeing in the…

Thank you, Pat. And good morning all. The end of 2016 was characterized by historical snowfalls in North Dakota, I've heard was the third worst snow event on record for the state. These events created delays with respect to construction activities and production, but will not have a long-term impact and only a minimal impact on fourth quarter activities. On the call - on the last call we updated you that we're mechanically complete on approximately 50% of the 30 mile pipeline project we were building on the Ft. Berthold Indian reservation, and had initial production of 2500 barrels per day flowing at that time. Before stopping during the height of the winter storms, we had initial production of approximately 15,000 barrels per day flowing. We have since resumed construction and are over 97% complete with the expansion with only the tie-ins were about 10 well past to finish. Last February, we provided guidance, we expected average 2016 natural gas volumes to be higher than average 2015 volumes and that we expected crude volumes to be essentially flat, despite the slowdown in activity that was experienced across the basin in 2015 and expecting shut-ins to protect nearby wells during frac For 2016, our Badlands natural gas volumes increased 6% versus 2015, and our crude volumes were down only slightly compared to 2015. During the fourth quarter, we tracked well shut-ins for fracture protection, and we estimate we had approximately 15,000 barrels per day shut-ins by our customers, which coupled with weather created headwinds first in the fourth quarter. Looking forward to the rest of 2017, we continue hear positive indications of research [ph] and likely to increase activity on our dedicated acreage; assuming crude prices stabilize around $55 per barrel. For the Badlands in 2017, we expect average crude and gas volumes to be higher compared to 2016. Giving Targa's attractive per unit margins for both gas and crude oil in the Bakken and available capacity in our Little Missouri plants, we are poised to benefit with any uptick in drilling activity. I'll now turn the call over to Scott Pryor, who leads our downstream business unit. Scott?

Thanks, Danny. As most of you know, my team and I lead the downstream business. Starting with LPG exports, 2016 was a really solid year for Targa as we outperformed our guidance for the year, despite some volatile market dynamics. Fourth quarter LPG export volumes were 6.3 million barrels per month, which exceeded the guidance provided on our third quarter earnings call of at least 6 million barrels per month and volumes would have been higher, if not for unseasonable fall delays during the latter part of December. Our fourth quarter LPG export volume performance was a combination of term and spot contracts, which is typical and what you should expect to be the case going forward. Globally, there was an increase in LPG demand during the quarter from places like Indonesia, India, China, Africa and Europe, relative to those market trends, Targa is well positioned to benefit from short-term opportunities and as a part of a longer term contract portfolio management. Vessels leaving our facility continue to move to destinations somewhat consistent with previous quarters, with approximately 64% going to the Americas and 36% to areas such as Europe, Africa and Asia in the fourth quarter of 2016. We did see more cargoes moving to Europe in the fourth quarter, due in large part to the weather and our volumes to the Americas continued to grow, even if the percentage of our overall volume is slightly lower. Our full year 2016 average of 5.5 million barrels per month exceeded the guidance that we provided last February, when we said that we expected to export at least 5 million barrels per month of LPGs. We are particularly proud of our results given some of the global market disruptions in the summer. As previously discussed, those market disruptions had a minimal…

Thanks, Scott. We've covered a lot of ground this morning. Let me briefly summarize our new public expectations or quote on quote guidance provided today. For 2017, we expect dividend coverage in excess of one times assuming, a 2017 dividend 364 per common share. We estimate at least $700 million of attractive growth capital spending based on the projects we highlighted and expect $110 million of maintenance capital spending. We expect average 2017 Permian basin volume growth of approximately 20% over average 2016. In the Badlands, we estimate higher crude and gas volumes year-over-year. In South Texas, we estimate higher average Inlet volumes year-over-year and for our overall field G&P Inlet volumes, we expect at least 10% growth in 2017, compared to average 2016. Downstream, we have export services of approximately two thirds of 7 million barrels per month contracted for multiple years, in each of multiple years. With that summary, and our comments today. I hope you have also heard we are optimistic about the current environment. Thanks in large part to our team’s successful navigation of 2015 and 2016 and the activity levels of customers who also successfully navigated such waters. I am so proud of the work of our employees over the last couple years and a lot of my excitement is driven by the enthusiasm that I am hearing from them across the company relative to the opportunities that they are seeing in the market. In conclusion, looking forward to the rest of 2017 and beyond, we have a number of attractive capital projects identified or underway, and expect to see continued opportunities to build out infrastructure around our assets at compelling returns. We are hopefully soon closing an acquisition that knits together very well with our existing assets and provides additional runway for growth in the most active G&P areas in the country. And we are well-positioned with our existing asset footprint to benefit from domestic market themes, such as ethane recovery, increased G&P activity in the best basins AND increased domestic NGL production, these things, combined with Targa positioning and Targa execution should create upside for our investors. So with that operator, please open up the line for questions. Thank you very much.

[Operator Instructions] And our first question comes from the line of Brandon Blossman of Tudor, Pickering, Holt & Company. Your line is now open.

Good morning, Brandon.

Hey, good morning.

Morning.

I hesitate to ask, but I'm going to do it. LPG recontracting, Joe Bob, I think the term you used was attractive rate. What's the point of comparison for attractive? Is that spot rates, current spot rates, historical contracted rates, something in between, or something else?

Brandon, you win, that we did predict that was the first question and we also predicted that Joe Bob wouldn't answer, which is why Scott is going to answer.

Brandon, thanks for the question. We did anticipate it to a certain degree. What I would say is, is this that, when we first started our Phase I and Phase II export projects and contracting for those, those were at very, very attractive rates and these attractive rates that we have out there and we are constantly contracting going forward, and we are working our contract portfolio on a term basis regularly. So we are very happy with the rights that we have. You hear a lot of times in the marketplace customers that may be trying to mitigate some of their take-or-pay requirements and you hear what I would refer to as re-trade spot values, that are relatively low rates in my opinion. So these are attractive compared to those types of rates.

Okay, that's actually more than I expected. Thank you, Scott.

Because it was Scott instead of Joe Bob, Brandon.

Okay. How about - this is hopefully fairly easy. Frac Train 6, what do you need to see to sanction that project and what's the timeline between sanction and online date?

Section is an interesting word. We have said for some time and we realize that, that it’s not a question of it, just a question of when on Train 6. We are not completely fallen the Targa portfolio of Mont Belvieu-based fractionation, but we don't have a whole lot of room, and we are filling up that room primarily based on Targa's increasing equity barrels flowing to our fractionation. We also want to be able to meet the needs of our customers and if we stay at current price levels, there is going to be a need for additional fractionation. From the time we actually break ground on that, you've seen based on our past track record that that can be done in about a year. Can we do a little faster? Sure, if we were and I don't expect this to be the case, kind of a pushing that ends of the contract without renewal process. We might get started and move a little bit slower. But on average from the time we break ground and people would notice it really quickly when we broke ground and probably tell the markets at the same time, you could count on roughly a year.

So, absolutely no risk that it gets too tight at Mont Belvieu? You guys will meet demand as needed?

I think there is risk. It gets too tight at Mont Belvieu at some point because it does take time to build these. At the same time Targa in particular has a portfolio that allows us a little bit of tightness relief valve by pushing NGLs to Lake Charles to fractionate on a temporary basis.

Understood. All right, thank you Joe Bob. I'll leave it there.

Thank you. And our next question comes from the line of Jeremy Tonet of JPMorgan. Your line is now open.

Good morning.

Hey, good morning.

I just want to dig in on the Permian a bit more here. And I was wondering if you might be able to provide us what type of - as that ramps, what type of exit rate - kind of if you look at 4Q '17 versus 4Q '16, how that might look, and if there's any color you could provide kind of on same-store sales without Outrigger? Just trying to calibrate our models here? Thanks.

Understood, same-store sales is a really interesting question, if take that all the way down to the well, all of the new horizontal wells start up at higher rates, have a fairly rapid first your decline and then that decline slows down. We aren’t about one well at a time. In fact, we hook up entire drilling pads and tank batteries behind - and pads behind existing tank batteries, I would say it’s a multi-store equation, even at the most disaggregated of our connections.

And that also makes it capital efficient for our connections. Exit rate for 2016 compared to '17, compared to exit rate 2016 is not granularity we're providing for you right now. And we have multiple forecast, I hope it helps you calibrate your models to look at about 20 - and this is going to be precisely 20, frankly I would take the overall 20% of Targa's Permian in 2017, relative to 2016.

And just to add to that Joe Bob, I would say when we look at our growth out on the Permian, we see growth really pretty steady across 2017. I don't know that we've forecasted a big step change in the quarter versus the other. There is variability with when some of our customers connect the wells, so it won't be smooth, but our estimate is for a pretty steady ramp across the year, it’s going to be wrong in any given quarter, but we see continued growth just throughout the year.

Okay. Matt, I just want to pick up on some of your comments as far as growing coverage, and just wondering if you could tie any numbers in there, kind of how you think about it philosophically as far as what type of coverage or range of coverage would make sense and leverage employees before you thought about dividend growth.

Yes, we talk about it, we intentionally left out any kind of number to put in there, but I guess, what I would say is you know, coming out of the environment we were in and looking ahead of the growth opportunities we have, we have $700 million of growth CapEx here which we anticipate to grow significantly. And we're just - with all the opportunities that we have, we want to take care the balance sheet first. So that’s going to be our first priority. A three to four times target ratio for the partnership, we don’t really plan to change that. We think over time we'll get our consolidated into that range. But don't necessarily have to solve for that no right up front. So I think it’s really just priorities for us and our priorities is going to be on taking care of the balance sheet.

Okay, great. That's helpful. That's it for me, thank you.

Okay, thanks.

Thank you. And our next question comes from the line of Chris Sighinolfi of Jefferies. Your line is now open.

Hi, Chris.

Hey. Good morning, Joe Bob, how are you?

Good.

I just had a question. I was looking at the slide presentation, and noticed, on the Joyce plant in West Texas, $90 million of spend for the 200 million of gas processing capacity seems very attractive relative to the typical costs we've seen from you and others in the past. So I am just wondering if there's something unique about that facility or something about that region in general that maybe affords it more economic investment on these types of things going forward?

You picked up on it. First I'd say I am very, very proud of our engineering group working on different way of approaching these cost and they were able to - you can see it relative to our press events, figure out ways for this to be less costly relative to other 200 million a day plants, built in a different time and a different cost in a slightly way. More importantly we like to thank that we've learned things along the way, a very experienced in building those plants in West Texas and can hold on, capture some of those costs going forward. It would not be fair to - not count the fact that because it's pretty close to another plant we've gained some infrastructure advantages by being close to that plan and every plant comes with associated infrastructure spending and we might have had less on this.

And just to add to that Joe Bob, when you look at the all in cost for the plant and related infrastructure it is cheaper than our historical spend for a plant, but that 90 it is also is net, so its 73% interest, so that’s our share of the plant, so the growth is a bit higher than that.

Okay. That's helpful, Matt. But I guess, in relation to Jeremy's question, I think about some of the returns, we should - opportunities like this where you have something located close to an existing asset, you can extract the costing improvement. When you bid that plant out or sell that capacity, we should think - is it incorrect to think that's a better return project, therefore you basically get to capture that cost improvement?

Yes, out of return.

Yes, as we're able to reduce the cost and plan and as were adding more plants, we're going to continue to do everything we can to even continue to drive those cost down.

I would like add, any plant being added to a multi-plant, interconnected multi-system, set of infrastructure has advantages, cost advantage, asset flexibility advantages, reliability advantages and you are sort of touching over there.

Okay, great…

I think, I would add one more thing too and that is, we are doing it at a lower cost with the same efficiencies and capabilities to process our gas.

Okay. I guess switching gears a little bit, I have two other remaining questions if I could. Matt, first, I guess, on that NGL sensitivity for '17, it looked like it's escalated a touch from what we were sort of seeing for 2016. I'm just wondering what's driving that. It looks like you're more hedged now, so I'm just wondering. Is that net to the sensitivities on hedges or is there a mix shift in the contracts? Any dynamic around maybe what's shaping that would be helpful.

Yes, I think that’s likely the volume outlook as we see growth in not only inlet, we're going to see increased NGL production growth too. So we have - we do have some more hedges in place, but then we do have more equity volumes from the growth in our business. So it’s right off of those business.

Okay. And then that's helpful. And then, finally, I guess I remember from the 10-K from last year that you had I think it was the Velma agreement with OneOK in the SouthOK system that was set to expire at the end of the year and you were planning to move that volume on to your own downstream network. I don't think the volumes were ever quantified, but I'm wondering, now that that agreement presumably has expired, if you offer any color on that, maybe what the uplift might be on your own downstream position from that contract expiration.

Yes, I mean, we've got a number of different arrangement at different plants and we're always looking to try and get as many volumes as we can through our downstream assets. I don’t recall the term of that exact one that you're referring to.

But across the portfolio.

Okay, I figured it might've been larger - it was called out.

Across the portfolio, Scott is now kicking me under a wide table here. Across the portfolio we are always trying to control more liquids instead of less liquids. You should assume that we're working on that and you should also presume that we're probably not going to dissect it into individual agreements and continue to describe them publicly. There was greater visibility on some of those agreements….

Okay. I didn't know if those were because they were legacy Atlas or because they were significant in size, but they were denoted, and that's the only reason I brought that one up…

Okay.

Okay. Thanks a lot guys.

Okay, thanks.

Thank you. And our next question comes from the line of Darren Horowitz of Raymond James. Your line is now open.

Good morning guys. Regarding the comments that have been made around equity NGL volume exposure, pro forma the Permian acquisition being integrated by the end of the year, you're going to have obviously gathering capacity over 2 Bcf a day, so more rich gas coming across the system through that, and also acres dedications. How much equity barrel or commodity sensitive marketing exposure do you want to have pro forma the assets being integrated? And could it be a situation where the incremental fee-based EBITDA from the organic growth projects grows consistent with that equity NGL exposure such that the amount of margin that's actually exposed still stays around 30%?

Yes, it’s good question Darren, we have a mix. So it really does depend on just what growth we see from those assets relative to our legacy assets, and price, the Outrigger acquisition it’s essentially all fee-based, as you recall, so its 98%. We're going to see significant growth. That’s going to be pushing dollar fees higher, so then it’s just really a matter of what happens to commodity prices and our volume that are - on WestTX and other areas where as primarily percentage of proceeds.

Okay. And then just one quick follow-up question on the Permian Basin G&P natural gas inlet volume growth, recognizing that it's really going to start picking up pro forma the asset integration, but I'm just wondering. From a timing and magnitude perspective, how pronounced do you expect the back half of your step change to be? And can you give us at least your preliminary thoughts of where you think, exit 2017, Permian Basin G&P natural gas inlet volumes could be versus day one when those assets are integrated?

Yes, it sounds lot like a question we got earlier of the –on the kind of volume ramp. I think as we think about Permian growth across '17, I think we're going to see a steady ramp in volume. At times there are periods where a bunch of compressor stations do come on and we do get some kind of intermediate step changes, but we don't have really good visibility on when those occur, at this second our forecast is for a steady ramp of up of Permian volumes really from kind of now through the end of the year and then continuing into '18.

And any individual producer that shut-in wells to protect while they are fracing have had drilling and pad completion, may be more in drilling mode then completion mode at a particular point in time. But those things tend to even out with each other. I don't think even though we analyze it hard and run lots of forecast, I don't really believe we can give you much more color, rather than to say, its steadily increasing, which was perhaps, that’s our expectation, it’s going to be what it’s going to be, but is going to be up into the right. And 20% average to average is pretty nice growth, and we are not trying to imply that we've got one percent positional of that already…

I appreciate that, Joe Bob. And then if I could, just one bigger picture follow-up. And I appreciate the color on this. But when you've outlined the opportunities for example to connect the Delaware system and the Sand Hills and what you're going to do in the Midland with the legacy West Texas assets and also talked about what's going on in Howard and Martin and Borden Counties, where do you see the biggest area of incremental opportunity for you, just from a system leveraging perspective?

I think we really - we had phenomenal position in the Midland with our existing assets, and we were kind of pushing into the Delaware's for this acquisition with the Outrigger assets, giving us a really good footprint in the Delaware to grow. I think we feel really good about both the Delaware site in the Midland basin.

They are both in a very good category, differentiating among that I don't think it’s particularly helpful. It will be - what the producer is doing, we know what the future looks like, in the Midland we've been there, we see it, we've got partner who is highly communicative with us and we're certainly getting closer to closing and with closing we can have been better communication with producers on the Delaware side.

Thank you very much.

Okay. Thanks, Darren.

Thank you. And our next question comes from the line of Danilo Juvane of BMO Capital. Your line is now open.

Good morning. Most of my questions have been hit. I did have one quick follow-up. So in the Downstream segment, OpEx picked up I think 10% year-over-year. I think you mentioned the compensation was largely due to that increase. But if you exclude that for 2017, how should we think about OpEx for the Downstream segment?

We had a couple of factors hitting OpEx for Downstream, we had the Train 5 coming on and then we also had commodity prices, gas prices move up on a year-over-year, a lot of that OpEx is passed through, the OpEx increases and that’s a variable component to the fee that is passed back to fractionation customer. So part of it just going to depend on where essentially commodity prices are a bit on OpEx' then Train 5 coming on that was the other increase that you saw.

But you should not expect particularly years, to years a radical step function of that increase in Train 5 on non-fuel based operating cost that there was also an increase in Train 5 fuel based operating cost.

Okay. That's it for me. Thank you

Thanks.

Thank you. And I am showing no further questions at this time. I would now like to turn the call over to management for closing remarks.

Thank you very much operator. And thanks to everyone on the call for the patience with the large amount of ground we covered. And with our admittedly typical reticent on Q&A. We look forward to 2017 and for performing for our investors in 2017 and look forward to the next call, next time we'll be talking to you. In the meantime, feel free to contact Lou, Jen, Matt or any of the rest of us. Thank you very much.

Ladies and gentlemen, thank you for participating in today's conference. This concludes today’s program. You may all disconnect. Everyone have a great day.